Pressure Control System and Optional Whipstock Repositioning System for Short Radius Lateral Drilling

ABSTRACT

An apparatus and method for pressure control of a tool string and for repositioning of a whipstock that includes an upper sealing mechanism capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole, a chamber connected to the upper sealing mechanism, the chamber having a length greater than the tool string and positioned at least partially within a wellbore and a lower valve connected to the distal end of the chamber within the wellbore wherein the tool-string can be isolated within the chamber from wellbore pressure. A lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within the wellbore, an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock and a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present filing claims priority to provisional patent application62/284,853 filed on Oct. 13, 2015.

FIELD

The present invention relates to an improved system for easily,economically, and safely working-over or completing wells involvingshort radius lateral drilling procedures. This invention allows theoperator to maintain pressure control and to efficiently reposition awhipstock during short radius laterals drilling procedures.

BACKGROUND

Natural resources such as oil and gas located in a subterraneanformation can be recovered by drilling a wellbore down to thesubterranean formation, typically while circulating a drilling fluid inthe wellbore. The wellbore is drilled with the use of a tool stringconsisting of drill pipe, various tools and having a drill bit on thedistal end. During the drilling of the wellbore drilling fluid istypically circulated through the tool string and the drill bit andreturns up the annulus between the tool string and the wellbore. Afterthe wellbore is drilled typically the tool string is pulled out of thewellbore and a string of pipe, e.g., casing, can be run in the wellbore.The drilling fluid is then usually circulated downwardly through theinterior of the pipe and upwardly through the annulus between theexterior of the pipe and the walls of the wellbore, although othermethodologies are known in the art.

Slurries such as hydraulic cement compositions are commonly employed inthe drilling, completion and repair of oil and gas wells. For example,hydraulic cement compositions are utilized in primary cementingoperations whereby strings of pipe such as casing are cemented intowellbores. In performing primary cementing, a hydraulic cementcomposition is pumped into the annular space between the walls of awellbore and the exterior surfaces of the casing. The cement compositionis allowed to set in the annular space, thus forming an annular sheathof hardened substantially impermeable cement. This cement sheathphysically supports and positions the casing relative to the walls ofthe wellbore and bonds the exterior surfaces of the casing string to thewalls of the wellbore. The cement sheath prevents the unwanted migrationof fluids between zones or formations penetrated by the wellbore.

The drilling of a horizontal well typically involves the drilling of aninitial vertical well and then a lateral extending from the verticalwell which arcs as it deviates away from vertical until it reaches ahorizontal or near horizontal orientation into the subterraneanformation.

In short radius drilling specialized tools are swept around a tightradius of a whipstock and are then used to form lateral boreholesradiating outward and into the subterranean formation. Short radiuslateral drilling is distinct from more-familiar conventional horizontaland coil tubing drilling. In conventional horizontal and coil tubingdrilling procedures, the drilling tools are swept around a radius or“heel” that is hundreds or even thousands of feet in size. That is, inboth of these procedures virtually all of the change in direction takesplace outside of the wellbore proper. By contrast, in short radiusdrilling, the primary change of direction occurs inside of the wellboreitself—that is, it occurs literally in the matter of a few inches.

As wellbores suited to this procedure commonly have a diameter ofbetween about 4½″ to 7″, this equates to radii of between about 2¼″ toabout 3½″ inches. In many short radius lateral drilling procedures afull 90 degree arc or “heel” is completed within the wellbore—that is,within about 0.25 ft (3 inches). This contrasts markedly with coiledtubing drilling, which often requires on the order of 250 feet and withconventional horizontal drilling which can utilize on the order of 2,500feet for a full 90 degree heel. Said in other words, conventionalhorizontal drilling technologies operate at a scale 3 to 4 orders ofmagnitude larger than those of short radius lateral drillingtechnologies.

Short radius lateral drilling procedures entail the placement of thewhipstock within a wellbore. Sometimes the whipstock is run on the endof upset or production tubing. Typically, the whipstock is locked intoposition within the wellbore at a specific elevation and azimuth bymeans of a packer. Many such packers are set by twisting the productiontubing at the surface; and, in turn, rotating the attached whipstockdownhole. Often, the packer is set or locked into position by applying apick-up (tension) or set down (compression) force on the productiontubing string. Sometimes it is desirable to direct the lateral wellborein a particular azimuth—such as to intersect a preferential fractureplane. This can be accomplished when setting the anchor by the aid of agyro or similar orienting indicator. If the whipstock is aiming in thewrong azimuth, the packer can be unset, twisted and then reset in thecorrect direction.

During short radius drilling procedures, specialized tools are moveddown the wellbore and are directed at the casing (if present) and intothe earthen formation by means of the whipstock. A variety of tools canbe used to form the laterals in short radius lateral drillingprocedures. For example, sometime a high-pressure jetting nozzle-head isused in an attempt to erode or dissolve the rock. An example of thismethod can be found in U.S. Pat. No. 8,424,620 by Perry et al andincorporated herein by reference. In other cases a motor drives a sortof flexible drilling shaft and attached cutting head as described inU.S. patent application Ser. No. 13/226,489 by Savage and incorporatedherein by reference; while in yet other cases ballistic, laser or othermeans can be employed to form the lateral. In the case of a flexibledrilling shaft, the lateral borehole is formed by means of drill bitwhich mechanically cuts into the earthen formation.

In further contrast with conventional horizontal and coiled tubingdrilling, because of the small sizes involved in short radius lateraldrilling, any relatively long or larger diameter tools in thetool-string, such as a mud motor, cannot transition around the tightradius of the whipstock; and hence, these items never exit the wellbore.Thus, the only portions of the drill-string to exist the wellbore andextend into the lateral borehole is the lower portion, which must besufficiently flexible so as to transition thru the tight radius of thewhipstock.

After a given lateral is drilled, the whipstock can be rotated to a newazimuth at the same elevation and another lateral can be drilled. Inother instances, the whipstock is moved to a new elevation, where one ormore additional laterals are formed. Short radius lateral drillingprocedures can be used in conventional vertical wells, horizontal wells,slant wells or even multi-lateral wells; and, on cased or open-holecompleted wells. While many of these laterals exit the wellbore casingat a full 90 degrees, it is possible for laterals drilled with shortradius lateral drilling tools to exit the wellbore at anywhere betweenabout 45 to slightly over 90 degrees.

The tool-string used to form the lateral is often maneuvered by means ofa coiled tubing unit (CTU), with the coiled tubing acting as both acontrol-line and a source of fluid for the tool-string. It is alsopossible, however, to run certain formation drilling tools on the end ofa wireline unit or by means of jointed tubing running to the surface.Most commonly, however, a wireline or CTU serves as the control-line andthe control-line is run thru production tubing.

Historically, short radius lateral drilling procedures have beenperformed as an economical work-over procedure on marginal, low-pressurewells and, sometimes even on “dead” wells. On such wells pressurecontrol measures were sometimes neglected or consisted of a relativelylow-pressure Guiberson style “oil-saver” apparatus.

Positioned above the wellhead, the oil-saver acts as wiper on thecontrol-line. If further engaged, the oil-saver can provide a modestseal to about 3,000 psi against the control-line. Aside from their lowpressure control rating, using only an oil-saver is also problematicbecause the well must be opened to the atmosphere whenever thecontrol-line and attached tool-string are placed into or retrieved fromthe wellbore. This occurs because the packing glad, the sealingmechanism within the oil-saver, must be removed from the oil-saver inorder to pass the tool-string.

As mechanical short radius lateral drilling systems drill out furtherthey can be used to complete new wells, such as when fracture treatmentisn't technically or economically feasible. To work on such wells,however, short radius lateral drilling systems must develop and employimproved solutions to address pressure risks. Concerns of high-pressurealso pertain to mature oilfields, however, because of the possibility ofencountering “kicks” from high-pressure fractures or zonal compartments.

The typical pressure control option is a lubricator stack. Lubricatorstacks essentially consists of a lower valve positioned near groundlevel and attached to the wellhead and one or more intervening joints oftubing connected to a second upper seal or valve. With the upper sealopen and the lower valve closed, a tool-string connected to acontrol-line can be safely inserted into the lubricator stack. Once theentire tool-string has been inserted in the lubricator stack, the upperseal can be engaged or “packed off” to form a seal around thecontrol-line. The lower valve can then be opened and the tool-stringsafely tripped downhole by lowering or “snubbing” in the control-line.Oftentimes, the lubricator stack is positioned above a blow-outpreventer (BOP), attached to the wellhead.

As short radius lateral drilling procedures drill out further, itstool-strings become increasingly longer. For example, to form a 75 footlong lateral might require a tool-string having a length of over 100feet. The extra 25 feet or so of length accounted for by items such as adownhole motor, check valve, swivel assembly, shear sub and connectionsub (in addition to the 75 foot length of the flexible portion of thetool-string). In order to accept such a large tool, however, wouldrequire that this lubricator stack be at least 100 foot tall.

This presents sizable challenges, complications and costs. For example,a taller lubricator stack requires employing significantly larger andmore expensive cranes or rigging mechanism. The tool-strings for lateraldrilling are placed into the top of the lubricator stack. As such, thecrane must be able to reach significantly higher than the top of thelubricator stack in order to suspend that tool-string over the top ofthe lubricator stack. Moreover, the crane is not a single use item thatcan be dismissed after its first use. Instead, it must be presentwhenever the tool-string is inserted into or removed from the wellbore.As short radius lateral drilling procedures typically entail manytool-string trips over several days (or perhaps even weeks), the cranecosts alone can render the procedure prohibitively expensive.

While the direct cost of a large crane is one consideration, it is notthe only one. For example, with such a tall pressure control/lubricatorstack even mild wind-gusts run the risk of damaging or breakingequipment. The job can be shut-down, but this is highly undesirable.More importantly, such a tall lubricator stack entails subjectingpersonnel to the significant safety-risks associated with working atever increasing heights. Again, personnel may need to work at over 100feet in height to place a long tool-string into the top of a talllubricator stack and then make-up the necessary tool connections.

An alternative is to use weighted drilling muds to provide wellborepressure control. This option, however comes with its own technical andeconomical complications. Besides the added cost of the drilling mud andassociated freight charges, there are drilling fluid compatibility andformation damage risks. Often these risks/costs render this optioninfeasible in practice, given the requirement that this procedure mustoffer an economical well stimulation.

Because of the above complications and costs, full pressure control israrely if ever used currently on short radius lateral drillingprocedures, therefore well work-overs that are likely to encounter highpressures are simply avoided. This is an unacceptable situation andclearly an easier, more economical and safer solution which maintainsfull pressure control throughout the duration of the procedure isneeded.

A further and inter-related problem with the current paradigm of shortradius lateral drilling pertains to the method of repositioning thewhipstock. At present moving the whipstock to a new elevation is done bya full-sized work-over rig which must be capable of handling the heavyupset or production tubing sting. If a tall lubricator stack were inplace, it must first be rigged-down and set aside so the work-over rigcan gain access to the production tubing. Given the heights and weightsinvolved, this is no small endeavor. This step alone adds considerabletime, costs and risks to this already “economically-sensitive”procedure.

Short radius lateral drilling procedures typically take about 1-2 dayper lateral and, oftentimes between 4 and 8 laterals are created from awellbore. Under the current norm, the work-over rig stays on locationfor the duration of the procedure. This adds significant costs as it isnot uncommon for the work-over rig to be on location for a week or moreand sometimes for several weeks. With current commercial day-rates forwork-over rigs at around $3,000 per day, this cost alone can readilyexceed $15,000. An alternative, is to release the work-over rig (toperform other jobs) and then call it back only when it is needed a dayor two later (to again move the whipstock). This option is alsounsatisfactory, however. Sometimes the work-over rig becomes delayed onanother job and if no other work-over rig is available, one incurscostly downtime. Of course, even if the work-over rig is available, onestill incurs extensive unproductive time and cost associated with:mobilizing the work-over rig and crew to the wellsite; positioning andrigging up; and then, rigging-down and demobilizing the work-over rig.All of these steps can easily take 4-6 hours on a typical procedureabove and beyond the actual time spent repositioning the whipstock. Thisinefficient situation can easily increase the total cost of short radiusdrilling procedures by 25% or more.

Thus, a need exists for a practical system in short radius lateraldrilling that addresses the following three issues: a more thoughtful,efficient and economic means for maintaining well pressure control; anefficient and economical means to reposition the whipstock; and a safeand easy means for field personnel to get tools into and out of thewellbore.

SUMMARY

This disclosure provides an efficient and economical system and methodto control well pressure during short radius lateral drillingprocedures. This system eliminates the need for a tall lubricator stackpositioned high above the wellbore and in so doing dramatically improvesthe safety and efficiency of deploying short radius lateral drillingprocedures. In certain applications, an integrated whipstockrepositioning system can also be used to further improve the efficiencyand reduce the cost of short radius lateral drilling procedures.

BRIEF DESCRIPTION OF DRAWINGS

The accompanying views of the drawing are incorporated into and form apart of the specification to illustrate several aspects and examples ofthe present disclosure, wherein like reference numbers refer to likeparts throughout the figures of the drawing. These figures together withthe description serve to explain the general principles of thedisclosure. The figures are only for the purpose of illustratingpreferred and alternative examples of how the various aspects of thedisclosure can be made and used and are not to be construed as limitingthe disclosure to only the illustrated and described examples. Thevarious advantages and features of the various aspects of the presentdisclosure will be apparent from a consideration of the drawings.

FIG. 1 illustrates a tubing jacking system located above a wellbore withtubing running through the jacking system and into the wellbore.

FIG. 2 illustrates a tubing jack system above a wellbore with tubingrunning through the tubing jack and into the wellbore. A whipstock andanchor have been raised from a lower elevation where two lateralboreholes have been drilled, one lateral has already been formed at thenew elevation and the whipstock is positioned to drill another.

FIG. 3a illustrates a downhole valve, in the closed positioned, situatedinside a wellbore along a string of tubing. The valve has isolated thepressure inside the tubing from that in the wellbore. A downhole toolassembly, located above the valve in the tubing, cannot pass through theclosed valve.

FIG. 3b illustrates the downhole valve of FIG. 3a in the open position.The downhole tool assembly hanging above the valve can now be loweredthrough the valve.

FIG. 3c illustrates a downhole tool assembly running through the openeddownhole valve that has been positioned along a string of tubing.

FIG. 4 illustrates a downhole valve located inside a wellbore with saidvalve in the open position. A downhole tool assembly is passing throughthe valve and inside of the tubing. The downhole tool assembly isconnected to a control-line, in this case coil-tubing, which has beensnubbed through an oil-saver.

FIG. 5 illustrates a tubing jacking system used in conjunction with apressure control system comprised of a downhole valve and oil-saver. Adownhole tool has been tripped through the downhole valve on its waytoward a whipstock, positioned downhole on production tubing.

DETAILED DESCRIPTION

The present disclosure makes short radius lateral drilling proceduressafer and more economical by providing suitable well pressure controlwithout necessitating a tall, precarious and otherwise costly pressurecontrol/lubricator stacks. In addition, this integrated system can beused to negate the need for and cost of having a work-over rig onlocation to reposition the whipstock. The apparatus and method describedherein is particularly well suited to proving a means to work-overmarginal wells wherein even modest additional costs can quickly renderthe work-over procedures cost-prohibitive.

To provide well pressure control, this solution entails the usage of twopressure control mechanisms: one an upper seal and the second a lowervalve. Instead of locating both of these items above ground, however, asis the current lubricator stack paradigm, in this invention the upperseal is located at the surface, while the lower valve is locateddownhole in the wellbore.

Between the upper seal and lower valve is an extended chamber. Thischamber is long enough and of sufficient diameter to capture or“swallow” the longest tool-string used during the short radius drillingprocedure. This chamber is connected and seals to the upper seal and tothe lower valve. This system allows for isolation of pressure within thechamber from that found in the wellbore itself. This chamber can becreated by using one or more coupled joints of production tubing thatare then threaded to the upper seal and lower valve.

The lower valve could be positioned at any number of locations withinthe wellbore. For example, it might be located closer to the surface,toward a middle depth, or above but in proximity with a whipstock. Inembodiments, the downhole valve would be positioned about 150 feet abovethe whipstock that is attached to a production tubing string which runsto the surface.

The surface pressure control mechanism or upper seal can be an“oil-saver” system that seals onto the control-line that is used tomaneuver the downhole tool-string. As oil-savers are typically onlyrated to 3,000 psi, in certain embodiments, the oil-saver can bepositioned above a BOP to enable pressure control to higher pressures.

To maintain full pressure control during the short radius drillingprocedure, the pressure control system entails a second valve positioneddownhole. As discussed, above, this valve can be placed in-line with theproduction tubing string. The downhole valve may consist of any numberof designs capable of providing pressure isolation. For example, designsmight include: a flapper valve that can be toggled open or closed; aball-valve having a center “thru-hole”; or a set ofconcentrically-oriented bladders that can be inflated to seal againstone another.

In embodiments, the downhole valve can consist of a ball valve that isopened or closed by turning the production tubing string to which it isattached. In yet other embodiments, the downhole valve could be operatedby means of a hydraulic, pneumatic, or electrical conductor line. Ininstances where the downhole valve is operated by a separatecontrol-line, this control-line would also entail a sealing means whenrunning through the wellhead and in order to maintain pressure control.In yet other embodiments, the downhole valve could be activated by radiofrequency (RF) signal, in which case the need to provide an additionalsealing mechanism at the wellhead is negated.

Each of the designs herein would allow the operator to control theopening and closing of the downhole valve and hence isolate wellborepressure. When in the open position, each of these valves would allow alarge enough diameter passageway (e.g. 2″ to 3″) through which thetool-string and attached control-line could be traversed.

When the drill-string and control-line are above this lower valve or outof the well altogether, the downhole valve can be closed in order toprovide full isolation of pressure from above and below the valve. Onecan see that by opening the upper seal while the lower valve was stillclosed, the tool-string can be safely inserted into or retrieved fromthe wellbore, even if there is high-pressure in the well below the lowervalve. Once the tool-string and attached control-line have been insertedinto the pressure control system, the upper seal can then be engaged toseal around the control-line. At this point, the lower valve can beopened so the tool-string safely lowered or “snubbed” into the well withfull pressure control. Naturally, to remove the tool-string from thewellbore would essentially involve reversing the above steps.

An optional pressure release valve can be incorporated into the extendedchamber so that pressure in the chamber can be equalized slowly. Thatis, if there is an extreme differential pressure between the extendedpressure control chamber and the wellbore, the pressure release valvecan be used to slowly normalize these two different pressure levels.

As noted earlier, often it is desirable to repeat the short radiuslateral drilling procedure at multiple depths in a wellbore. Sometimesthe difference in depth might be a few inches while in other instancesit might be several hundred feet. Using the apparatus and methoddescribed below, one can efficiently add or remove joints of tubing fromthe production tubing string so as to properly reposition the attachedwhipstock. Moreover, this system can be seamlessly integrated with thepressure control system described above, or the two can be deployedindependently of one another.

The system to reposition the whipstock entails a dual-slip jackingsystem that engages and moves the production tubing and thereby movesthe attached whipstock. This dual-slip jacking system is positionedabove the wellhead and comprises an upper and a lower set of slips. Thesystem also includes a vertical lifting/lowering mechanism that can movethe production tubing by means of the upper set of slips. Positionedbetween the two sets of slips is the vertical lifting apparatus, whichmay be comprised of a set of hydraulic cylinders or threaded screws andjack-bolts.

When hydraulic pressure is applied to the cylinders they can lift theupper set of slips along with the production tubing and attachedwhipstock. By contrast the threaded screw and jack-bolt system wouldoperate by rotation of the screws, but the affect would be the same, thelifting or lowering of production tubing and whipstock via the set ofupper slips.

Obviously, if a packer attached to the whipstock has been set, it willfirst be necessary to unset the packer. As will be more fully evidentbelow, the system described herein can be efficiently used with commonpackers requiring twisting and vertical movement to be set/unset.

In certain embodiments the wellhead slips, traditionally located in thebowl at the top of the wellhead, will serve as the lower set of slips.The upper set of slips rest in an upper bowl that sits atop an upperplate. This plate would be thick and/or gusseted in order to resistbending when holding the weight of the production tubing. The productiontubing with attached whipstock can proceed through the lower set ofslips, through the upper plate and through the upper set of slips. Asthe upper plate is moved vertically, whether by the hydraulic cylindersor the jack bolts system, the upper slips grab onto the productiontubing and correspondingly move the attached whipstock.

In other embodiments, the set of slips normally positioned in theaforementioned wellhead bowl can be removed altogether and a speciallower plate can be threaded onto the wellhead. On the top of this lowerplate would be a new lower bowl in which is placed the lower set ofslips. Given the interference caused by the presence of the cylinders orthread-screws and jack-bolts, moving the lower bowl to this location hasthe advantage of improving access to this set of slips. This embodimentwould also have an upper plate on which sits an upper bowl and upper setof slips is positioned. Similar to the prior example, in thisembodiment, the production tubing runs through the lower plate and lowerslips as well as the upper plate and upper slips. Both the upper andlower plate would be thick so as to resist bending when holding theheavy production tubing string. In these embodiments, the hydrauliccylinders or jack bolt system would push against the lower plate whenlifting the upper plate.

While hydraulic pressure can cause the cylinders to extend and lift theupper plate, the upper plate can be lowered under the force of gravity,that is by removing the pressure on the cylinders. This contrasts withthe jack-bolt system wherein rotation is required to both raise andlower the entire system.

In certain embodiments, just below the upper or lower set of slips abearing set can be located. This bearing set can enable the easyrotation of the heavy upset tubing sting and attached whipstock. Thedesirability of easily rotating the heavy upset tubing string includesnot only the need to change the azimuth of the whipstock but also to setand unset the downhole packer. It should also be noted that this samebearing allows for easy operation of downhole valve systems that areopened/closed by means of rotation.

As noted above, certain short radius drilling procedures may requirethat the whipstock be raised or lower by a distance in excess of thesystem stroke length. In these cases, the lower set of slips can be usedto hold the production tubing as the cylinders or jack-bolts are resetto take another stroke. In this fashion, sequential strokes of thelifting system can be made to ultimately lift or lower the productiontubing great distances. Conversely, the jacking system can also be usedto lower the production tubing, attached whipstock and anchor.

With this dual-slip jacking system joints of production tubing can beeasily added or removed above the wellhead. In this fashion the top ofthe production tubing, where the oil-saver sits (for pressure control)can be set at a convenient working height.

This disclosure addresses two significant and unmet challenges forpractitioners of short radius lateral drilling: 1) it provides a safe,efficient and affordable means of assuring wellbore pressure controlthroughout the drilling procedure; and 2) it provides an easy andaffordable means to quickly reposition the whipstock.

To illustrate, FIG. 1 shows a tubing jacking system (25) located at thesurface and attached to a wellhead (9). The jacking system (25) includesa bottom plate (8), a lower slip bowl (4), lower slips (18), hydrauliccylinders (7) and pushrods (19), a top plate (6), bearing (5), upperslip bowl (3) and upper slips (17). The tubing (1) runs inside thewellbore (2) and is held by the jacking system (25). There is an anchor(15) and a whipstock (14) located on the end of the upset tubing (1).

FIG. 2 illustrates the tubing jacking system (25) attached to a wellhead(9) and comprised of a bottom plate (8), a lower slip bowl (4), lowerslips (18), hydraulic cylinders (7) and pushrods (19), a top plate (6),bearing (5), upper slip bowl (3) and upper slips (17). Tubing (1) runsinside the wellbore (2) and held by the jacking system (25). Thepushrods (19) have been extended, raising the tubing (1), whipstock (14)and anchor (15). A new lateral borehole (21) has been drilled at ahigher elevation than the previously-drilled boreholes (16) and thewhipstock (14) is oriented to create another borehole.

FIG. 3A illustrates a downhole valve assembly (11) positioned along astring of tubing (1) that is located inside a wellbore (2). A downholetool assembly (10) is positioned above the downhole valve assembly (11).The valve assembly (11) shows the sealing mechanism (12) of the valveassembly (11) in the closed position. The sealing mechanism (12)consists of a passageway (13), which can be opened or closed in relationto the tubing (1).

FIG. 3B illustrates a downhole valve assembly (11) located along astring of tubing (1) positioned inside a wellbore (2). A downhole toolassembly (10) has also been positioned inside of the string of tubing(1) and is situated above the downhole valve assembly (11). The sealingmechanism (12) of the valve assembly (11) is in the open position,aligning the passageway (13) with the string of tubing (1).

FIG. 3C illustrates a downhole tool assembly (10) running through theopened downhole valve assembly (11) that has been positioned along astring of tubing (1). The sealing mechanism (12) consists of apassageway (13) that is in the open position, allowing the downhole toolassembly (10) to freely pass through the valve assembly (11).

FIG. 4 illustrates a downhole valve assembly (11) position along tubing(1) with the sealing mechanism (12) in the open position. By virtue ofthe passageway (13) of the sealing mechanism (12) being opened i.e. inline with the upset tubing (1) a downhole tool assembly (10) has beenrun through the valve assembly (11). There is a packing gland (24) in anoil-saver (20) that seals against the control-line (22) that isconnected to the downhole tool assembly (10).

FIG. 5 illustrates a tubing jacking system (25) located on a wellhead(9) and comprising a bottom plate (8), a lower slip bowl (4), lowerslips (18), hydraulic cylinders (7) and pushrods (19), a top plate (6),bearing (5), upper slip bowl (3) and upper slips (17). A downhole valveassembly (11) is positioned along upset tubing (1) with the sealingmechanism (12) in the open position. The passageway (13) of the sealingmechanism (12) is in line with the upset tubing (1) and a downhole toolassembly (10) is running through the valve assembly (11) toward awhipstock (14) set on an anchor (15). There is an oil saver (20) at thesurface that used a packing gland (24) to seals against the control-line(22) holding the downhole tool assembly (10).

In an embodiment of the present disclosure an apparatus for isolatingwellbore pressure in short radius lateral drilling procedures includesan upper sealing mechanism located above ground level capable of sealingaround a control-line used to manipulate a tool-string used to form alateral borehole, a chamber connected to the upper sealing mechanism,the chamber having a length greater than the tool string and positionedat least partially within a wellbore, a lower valve connected to thedistal end of the chamber within the wellbore, wherein the tool-stringcan be isolated within the chamber from wellbore pressure.

In an embodiment the upper sealing mechanism is an oil-saver typesealing mechanism. In an embodiment the chamber comprises productiontubing. In an embodiment the lower ball valve is selected from one ofthe group consisting of: a ball valve, a flapper valve, a bladderinflated by gas, a bladder inflated by fluid, and combinations thereof.In an embodiment the lower valve when in the open position has an insidediameter capable of passing the tool-string there through. In anembodiment the lower valve is activated from the surface by one or moreof: pulling or pushing vertically on said apparatus; rotating the lowervalve; by means of an electrical, hydraulic or pneumatic line runningfrom the surface to the lower valve; or by means of radio frequency (RF)that communicates from the surface to the lower valve.

In an alternate embodiment an apparatus is used in short radius lateraldrilling procedures that allows for vertical repositioning of awhipstock that includes a lower set of slips positioned above a wellheadcapable of holding a tubing string and attached whipstock suspendedwithin a wellbore, an upper set of slips positioned above the lower setof slips and capable of supporting the tubing string and attachedwhipstock, and a vertical manipulation mechanism that can raise or lowerthe tubing string and attached whipstock by raising or lowering theupper set of slips.

In an optional embodiment the apparatus includes a bearing positionedbelow at least one of the upper and lower set of slips, said bearing(s)allowing the rotation of the tubing string, attached whipstock and anoptional anchor. Optionally the apparatus includes a bearing positionedbelow at least one of the upper and lower set of slips, said bearing(s)allowing the rotation of the tubing string, attached whipstock and anoptional anchor. Optionally the apparatus includes cylinders used tovertically reposition a plate on which supports the upper set of slips.

In an embodiment a method for repositioning a whipstock used in shortradius lateral drilling that includes providing an apparatus having alower set of slips positioned above a wellhead capable of holding atubing string and attached whipstock suspended within a wellbore, anupper set of slips positioned above the lower set of slips and capableof supporting the tubing string and attached whipstock, a verticalmanipulation mechanism that can raise or lower the tubing string andattached whipstock by raising or lowering the upper set of slips, andcylinders used to vertically reposition a plate on which supports theupper set of slips. The method includes engaging the cylinders tovertically reposition the tubing string and attached whipstock androtating the tubing string to change the azimuth of the attachedwhipstock.

In an alternate embodiment there is disclosed a method to maintainpressure control during insertion of a tool string used for short radiuslateral drilling procedures into a wellbore, providing an apparatushaving an upper sealing mechanism located above ground level capable ofsealing around a control-line used to manipulate a tool-string used toform a lateral borehole, a chamber connected to the upper sealingmechanism, the chamber having a length and diameter greater than thetool string and the chamber positioned at least partially within awellbore, and a lower valve connected to the distal end of the chamberwithin the wellbore. The method further includes closing the lower valveand opening the upper sealing mechanism, inserting the tool-string and aportion of an attached control-line into the chamber, engaging the uppersealing mechanism to seal onto the control-line, opening the lower valveand running the tool-string into the wellbore through the lower valve.

An alternate embodiment is a method to maintain pressure control duringextraction of a tool-string used for short radius lateral drillingprocedures. The method includes providing the apparatus described aboveand retracting a tool-string into the chamber from a location within thewellbore below the chamber, closing the lower valve, opening the uppersealing mechanism, retracting the tool-string out of the upper sealingmechanism.

In a further alternate embodiment there is disclosed a system forefficient short radius lateral drilling procedures comprising anapparatus for pressure control and an apparatus for repositioning of awhipstock. The system includes an upper sealing mechanism located aboveground level capable of sealing around a control-line used to manipulatea tool-string used to form a lateral borehole, a chamber connected tothe upper sealing mechanism, the chamber having a length greater thanthe tool string and positioned at least partially within a wellbore anda lower valve connected to the distal end of the chamber within thewellbore. The tool-string can be isolated within the chamber fromwellbore pressure. The system includes a lower set of slips positionedabove a wellhead capable of holding a tubing string and attachedwhipstock suspended within the wellbore, an upper set of slipspositioned above the lower set of slips and capable of supporting thetubing string and attached whipstock and a vertical manipulationmechanism that can raise or lower the tubing string and attachedwhipstock by raising or lowering the upper set of slips.

In an embodiment of the system the upper sealing mechanism is anoil-saver type sealing mechanism. In an embodiment the chamber comprisesproduction tubing. In an embodiment the lower ball valve is selectedfrom one of the group consisting of: a ball valve, a flapper valve, abladder inflated by gas, a bladder inflated by fluid, and combinationsthereof. In an embodiment the lower valve when in the open position hasan inside diameter capable of passing the tool-string there through. Inan embodiment the lower valve is activated from the surface by one ormore of: pulling or pushing vertically on said apparatus; rotating thelower valve; by means of an electrical, hydraulic or pneumatic linerunning from the surface to the lower valve; or by means of radiofrequency (RF) that communicates from the surface to the lower valve.

An optional embodiment of the system includes a bearing positioned belowat least one of the upper and lower set of slips, said bearing(s)allowing the rotation of the tubing string, attached whipstock and anoptional anchor. Optionally the apparatus includes a bearing positionedbelow at least one of the upper and lower set of slips, said bearing(s)allowing the rotation of the tubing string, attached whipstock and anoptional anchor. Optionally the apparatus includes cylinders used tovertically reposition a plate on which supports the upper set of slips.

The various embodiments of the present disclosure can be joined incombination with other embodiments of the disclosure and the listedembodiments herein are not meant to limit the disclosure. Allcombinations of various embodiments of the disclosure are enabled, evenif not given in a particular example herein.

While illustrative embodiments have been depicted and described,modifications thereof can be made by one skilled in the art withoutdeparting from the scope of the disclosure. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Moreover, the indefinite articles “a” or “an”, as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documents,the definitions that are consistent with this specification should beadopted. While compositions and methods are described in terms of“comprising,” “containing,” or “including” various components or steps,the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. Also, the terms in theclaims have their plain, ordinary meaning unless otherwise explicitlyand clearly defined by the patentee.

Depending on the context, all references herein to the “disclosure” mayin some cases refer to certain specific embodiments only. In other casesit may refer to subject matter recited in one or more, but notnecessarily all, of the claims. While the foregoing is directed toembodiments, versions and examples of the present disclosure, which areincluded to enable a person of ordinary skill in the art to make and usethe disclosures when the information in this patent is combined withavailable information and technology, the disclosures are not limited toonly these particular embodiments, versions and examples.

Numerous other modifications, equivalents, and alternatives, will becomeapparent to those skilled in the art once the above disclosure is fullyappreciated. While embodiments of the disclosure have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the teachings of this disclosure. The embodimentsdescribed herein are exemplary only, and are not intended to belimiting. Many variations and modifications of the disclosure disclosedherein are possible and are within the scope of the disclosure.

Use of the term “optionally” with respect to any element of a claim isintended to mean that the subject element is required, or alternatively,is not required. Both alternatives are intended to be within the scopeof the claim. It is intended that the following claims be interpreted toembrace all such modifications, equivalents, and alternatives whereapplicable. Other and further embodiments, versions and examples of thedisclosure may be devised without departing from the basic scope thereofand the scope thereof is determined by the claims that follow.

1. An apparatus for isolating wellbore pressure in short radius lateraldrilling procedures comprising: an upper sealing mechanism located aboveground level capable of sealing around a control-line used to manipulatea tool-string used to form a lateral borehole; a chamber connected tothe upper sealing mechanism, the chamber having a length greater thanthe tool string and positioned at least partially within a wellbore; alower valve connected to the distal end of the chamber within thewellbore; wherein the tool-string can be isolated within the chamberfrom wellbore pressure.
 2. The apparatus of claim 1 wherein the uppersealing mechanism is an oil-saver.
 3. The apparatus of claim 1 whereinthe chamber comprises production tubing.
 4. The apparatus of claim 1wherein the lower ball valve is selected from one of the groupconsisting of: a ball valve, a flapper valve, a bladder inflated by gas,a bladder inflated by fluid, and combinations thereof.
 5. The apparatusof claim 1 wherein the lower valve when in the open position has aninside diameter capable of passing the tool-string there through.
 6. Theapparatus of claim 1 wherein the lower valve is activated from thesurface by one or more of: pulling or pushing vertically on saidapparatus; rotating the lower valve; by means of an electrical,hydraulic or pneumatic line running from the surface to the lower valve;or by means of radio frequency (RF) that communicates from the surfaceto the lower valve.
 7. An apparatus used in short radius lateraldrilling procedures for vertical repositioning of a whipstockcomprising: a lower set of slips positioned above a wellhead capable ofholding a tubing string and attached whipstock suspended within awellbore; an upper set of slips positioned above the lower set of slipsand capable of supporting the tubing string and attached whipstock; avertical manipulation mechanism that can raise or lower the tubingstring and attached whipstock by raising or lowering the upper set ofslips.
 8. The apparatus of claim 7 further comprising a bearingpositioned below at least one of the upper and lower set of slips, saidbearing(s) allowing the rotation of the tubing string, attachedwhipstock and an optional anchor.
 9. The apparatus of claim 7 furthercomprising cylinders used to vertically reposition a plate on whichsupports the upper set of slips.
 10. A method of repositioning awhipstock used in short radius lateral drilling comprising: providing anapparatus comprising: a lower set of slips positioned above a wellheadcapable of holding a tubing string and attached whipstock suspendedwithin a wellbore, an upper set of slips positioned above the lower setof slips and capable of supporting the tubing string and attachedwhipstock, a vertical manipulation mechanism that can raise or lower thetubing string and attached whipstock by raising or lowering the upperset of slips, and cylinders used to vertically reposition a plate onwhich supports the upper set of slips; engaging the cylinders tovertically reposition the tubing string and attached whipstock; androtating the tubing string to change the azimuth of the attachedwhipstock.
 11. A method to maintain pressure control during insertion ofa tool string used for short radius lateral drilling procedures into awellbore, said method comprising: providing an apparatus comprising: anupper sealing mechanism located above ground level capable of sealingaround a control-line used to manipulate a tool-string used to form alateral borehole; a chamber connected to the upper sealing mechanism,the chamber having a length and diameter greater than the tool stringand the chamber positioned at least partially within a wellbore; and alower valve connected to the distal end of the chamber within thewellbore; closing the lower valve and opening the upper sealingmechanism; inserting the tool-string and a portion of an attachedcontrol-line into the chamber; engaging the upper sealing mechanism toseal onto the control-line; opening the lower valve; and running thetool-string into the wellbore through the lower valve.
 12. A method tomaintain pressure control during extraction of a tool-string used forshort radius lateral drilling procedures, said method comprising:providing an apparatus comprising: an upper sealing mechanism locatedabove ground level capable of sealing around a control-line used tomanipulate a tool-string used to form a lateral borehole; a chamberconnected to the upper sealing mechanism, the chamber having a lengthand diameter greater than the tool string and the chamber positioned atleast partially within a wellbore; and a lower valve connected to thedistal end of the chamber within the wellbore; retracting a tool-stringinto the chamber from a location within the wellbore below the chamber;closing the lower valve; opening the upper sealing mechanism; retractingthe tool-string out of the upper sealing mechanism.
 13. A system forefficient short radius lateral drilling procedures comprising anapparatus for pressure control and an apparatus for repositioning of awhipstock comprising: an upper sealing mechanism located above groundlevel capable of sealing around a control-line used to manipulate atool-string used to form a lateral borehole; a chamber connected to theupper sealing mechanism, the chamber having a length greater than thetool string and positioned at least partially within a wellbore; a lowervalve connected to the distal end of the chamber within the wellbore;wherein the tool-string can be isolated within the chamber from wellborepressure; a lower set of slips positioned above a wellhead capable ofholding a tubing string and attached whipstock suspended within thewellbore; an upper set of slips positioned above the lower set of slipsand capable of supporting the tubing string and attached whipstock; avertical manipulation mechanism that can raise or lower the tubingstring and attached whipstock by raising or lowering the upper set ofslips.
 14. The system of claim 13 wherein the lower ball valve isselected from one of the group consisting of: a ball valve, a flappervalve, a bladder inflated by gas, a bladder inflated by fluid, andcombinations thereof.
 15. The system of claim 13 wherein the lower valveis activated from the surface by one or more of: pulling or pushingvertically on said apparatus; rotating the lower valve; by means of anelectrical, hydraulic or pneumatic line running from the surface to thelower valve; or by means of radio frequency (RF) that communicates fromthe surface to the lower valve.
 16. The system of claim 13 furthercomprising a bearing positioned below at least one of the upper andlower set of slips, said bearing(s) allowing the rotation of the tubingstring, attached whipstock and an optional anchor.
 17. The system ofclaim 13 further comprising cylinders used to vertically reposition aplate on which supports the upper set of slips.